Methods of recovering a hydrocarbon material

ABSTRACT

A method of recovering hydrocarbons comprises introducing a suspension comprising nanoparticles to a material and contacting surfaces of the material with the suspension. After introducing the suspension comprising the nanoparticles to the material, the method further includes introducing at least one charged surfactant to the material and removing hydrocarbons from the material. Accordingly, in some embodiments, the nanoparticles may be introduced to the material prior to introduction of the surfactant to the material. Related methods of recovering hydrocarbons from a material are also disclosed.

CROSS-REFERENCE TO RELATED APPLICATIONS

This application is a continuation of U.S. patent application Ser. No.16/117,176, filed Aug. 30, 2018, which is a continuation-in-part of U.S.patent application Ser. No. 15/973,028, filed May 7, 2018, which claimsthe benefit under 35 U.S.C. § 119(e) of U.S. Provisional PatentApplication Ser. No. 62/504,731, filed May 11, 2017, the disclosure ofeach of which is hereby incorporated herein in its entirety by thisreference.

TECHNICAL FIELD

Embodiments of the disclosure relate generally to methods of obtaining ahydrocarbon from a material. More particularly, embodiments of thedisclosure relate to methods of recovering a hydrocarbon material from amaterial, such as from a subterranean formation, using nanoparticles andone or more charged surfactants, and to related methods.

BACKGROUND

Water flooding is a conventional process of enhancing the extraction ofhydrocarbon materials (e.g., crude oil, natural gas, etc.) fromsubterranean formations. In this process, an aqueous fluid (e.g., water,brine, etc.) is injected into the subterranean formation throughinjection wells to sweep a hydrocarbon material contained withininterstitial spaces (e.g., pores, cracks, fractures, channels, etc.) ofthe subterranean formation toward production wells offset from theinjection wells. One or more additives may be added to the aqueous fluidto assist in the extraction and subsequent processing of the hydrocarbonmaterial.

For example, in some approaches, a surfactant or solid particles (e.g.,colloids)) are added to the aqueous fluid. The surfactant or the solidparticles can adhere to or gather at interfaces between a hydrocarbonmaterial and an aqueous material to form a stabilized emulsion of one ofthe hydrocarbon material and the aqueous material dispersed in the otherof the hydrocarbon material and the aqueous material. Surfactants maydecrease the surface tension between the hydrocarbon phase and the waterphase, such as, for example, in an emulsion of a hydrocarbon phasedispersed within an aqueous phase. Stabilization by the surfactant orthe solid particles may lower the interfacial tension between thehydrocarbon and the aqueous phase and reduce the energy of the system,preventing the dispersed material (e,g., the hydrocarbon material, orthe aqueous material) from coalescing, and maintaining the one materialdispersed as units (e.g., droplets) throughout the other material.Reducing the surface tension increases the permeability and theflowability of the hydrocarbon material. As a consequence, thehydrocarbon material may be more easily transported through andextracted from the subterranean formation as compared to water floodingprocesses that do not employ the addition of a surfactant or solidparticles. The effectiveness of the emulsion is determined in large partby the ability of the emulsion to remain stable at wellbore conditions(e.g., high temperature, high salinity, etc.) and ensure mixing of thetwo phases.

However, application of surfactants is usually limited by the cost ofthe surfactants and their adsorption and loss onto the rock of thehydrocarbon-containing formation. Disadvantageously, the effectivity ofvarious surfactants can be detrimentally reduced in the presence ofdissolved salts (e.g., such as various salts typically present within asubterranean formation), in addition, surfactants may have a tendency toadsorb onto surfaces of the subterranean formation, resulting in theeconomically undesirable addition of more surfactant to the injectedaqueous fluid to account for such losses. Solid particles can bedifficult to remove from the stabilized emulsion during subsequentprocessing, preventing the hydrocarbon material and the aqueous materialthereof from coalescing into distinct, immiscible components, andgreatly inhibiting the separate collection of the hydrocarbon material.Furthermore, the surfactants are often functional or stable only withinparticular temperature ranges and may lose functionality at elevatedtemperatures or various conditions encountered within a subterraneanformation.

BRIEF SUMMARY

Embodiments disclosed herein include methods of recovering hydrocarbonsfrom a subterranean formation. For example, in accordance with oneembodiment, a method of recovering hydrocarbons from a subterraneanformation comprises introducing a suspension comprising silicananoparticles into a subterranean formation, contacting surfaces of thesubterranean formation with the suspension to form a layer of the silicananoparticles on at least some surfaces of the subterranean formation,after introducing the suspension comprising silica nanoparticles intothe subterranean formation, introducing a solution comprising at leastone anionic surfactant into the subterranean formation, and extractinghydrocarbons from the subterranean formation.

In additional embodiments, a method of recovering hydrocarbons from asubterranean formation comprises mixing silica nanoparticles having adiameter less than about 100 nm with a carrier fluid comprising brineand at least one anionic surfactant to form a suspension, introducingthe suspension into a subterranean formation having a temperaturegreater than about 50° C., and extracting hydrocarbons from thesubterranean formation.

In yet additional embodiments, a method of recovering hydrocarbons froma subterranean formation, comprises introducing a suspension comprisingnanoparticles selected from the group consisting of silica and aluminumsilicate into a subterranean formation, adhering the nanoparticles tosurfaces within the subterranean formation, and after introducing thesuspension comprising nanoparticles into the subterranean formation,introducing a solution comprising at least one anionic surfactant intothe subterranean formation.

In further embodiments, a method of recovering hydrocarbons comprisesintroducing a suspension comprising nanoparticles to a material,contacting surfaces of the material with the suspension, afterintroducing the suspension comprising the nanoparticles to the material,introducing at least one charged surfactant to the material, andremoving hydrocarbons from the material.

In additional embodiments, a method of recovering hydrocarbons comprisesintroducing a fluid comprising at least one charged surfactant andnanoparticles comprising aluminum atoms and silicon atoms to a materialat a temperature greater than about 50° C., and removing hydrocarbonsfrom the material.

In yet further embodiments, a method of recovering hydrocarbonscomprises introducing nanoparticles selected from the group consistingof silica, aluminum silicate, and alumina modified silica nanoparticles,and metal oxide modified nanoparticles, adhering the nanoparticles tothe material, and after introducing the nanoparticles to the material,introducing at least one surfactant to the material.

BRIEF DESCRIPTION OF THE DRAWINGS

FIG. 1 is a simplified flow diagram illustrating a method of obtaining ahydrocarbon material from a subterranean formation, according toembodiments of the disclosure;

FIG. 1A is a simplified schematic of an alumina modified silicananoparticle, according to embodiments of the disclosure;

FIG. 1B is a simplified schematic of a metal oxide modified silicananoparticle, according to embodiments of the disclosure;

FIG. 1C is a simplified schematic of a functionalized alumina modifiedsilica nanoparticle, according to embodiments of the disclosure;

FIG. 2 is a simplified flow diagram illustrating a method of obtaining ahydrocarbon material from a subterranean formation, according to otherembodiments of the disclosure;

FIG. 3A is a graph illustrating a percent of hydrocarbon recovery as afunction of a volume of fluid introduced into a core sample in alaboratory;

FIG. 3B is a graph illustrating a percent of hydrocarbon recovery as afunction of fluid introduced into another core sample in a laboratory;

FIG. 3C is a graphical comparison of hydrocarbon recovery with aflooding suspension comprising only surfactants and a floodingsuspension comprising nanoparticles and surfactants;

FIG. 4 is graphical representation of an amount of hydrocarbon recoveryfrom the sample responsive to a plurality of flooding operations; and

FIG. 5 is a graphical representation of an amount of hydrocarbonrecovery from another sample responsive to a plurality of floodingoperations.

DETAILED DESCRIPTION

Illustrations presented herein are not meant to be actual views of anyparticular material, component, or system, but are merely idealizedrepresentations that are employed to describe embodiments of thedisclosure.

The following description provides specific details, such as materialtypes, compositions, material thicknesses, and processing conditions inorder to provide a thorough description of embodiments of thedisclosure. However, a person of ordinary skill in the art willunderstand that the embodiments of the disclosure may be practicedwithout employing these specific details. Indeed, the embodiments of thedisclosure may be practiced in conjunction with conventional techniquesemployed in the industry. In addition, the description provided belowdoes not form a complete process flow for recovering a hydrocarbonmaterial from a material, such as from a subterranean formation, oilsands, bitumen, or from another material comprising one or morehydrocarbon materials. Only those process acts and structures necessaryto understand the embodiments of the disclosure are described in detailbelow. A person of ordinary skill in the art will understand that someprocess components (e.g., pipelines, line filters, valves, temperaturedetectors, pH meters, flow detectors, pressure detectors, and the like)are inherently disclosed herein and that adding various conventionalprocess components and acts would be in accord with the disclosure.Additional acts or materials to recover a hydrocarbon material may beperformed by conventional techniques.

FIG. 1 is a simplified flow diagram illustrating a method 100 ofobtaining a hydrocarbon material from a material (e.g., a subterraneanformation, oil sands, bitumen, etc.), according to embodiments of thedisclosure. The method 100 includes act 102, including mixingnanoparticles with a carrier fluid to form a first fluid comprising asuspension including nanoparticles dispersed in the carrier fluid; act104, which involves a flooding process in which the first fluid isintroduced to the material (e.g., into a subterranean formation, to oilsands, bitumen, etc.) and surfaces of the material are contacted withthe nanoparticles to adsorb the nanoparticles on surfaces of thematerial; act 106, including mixing at least one charged surfactant withanother carrier fluid to form a second fluid to be introduced to thematerial (e.g., injected into the subterranean formation, introduced tooil sands, bitumen, etc.); act 108, including introducing the secondfluid into the material; and act 110, including flowing (e.g., driving,sweeping, forcing, etc.) the hydrocarbons from the material (e.g., thesubterranean formation, the oil sands, bitumen, etc.) to a location awayfrom the material.

Act 102 may include mixing nanoparticles with a carrier fluid to form afirst fluid comprising a suspension including nanoparticles dispersed inthe carrier fluid. The carrier fluid may include water, brine, seawater,condensate, steam, etc., or combinations thereof. In some embodiments,the carrier fluid includes brine, such as may be encountered within awellbore. By way of nonlimiting example, a concentration of salts in thecarrier fluid may be between about 20 g salt/kg water and about 2,000 gsalt/kg water, such as between about 20 g salt/kg water and about 50 gsalt/kg water, between about 50 g salt/kg water and about 100 g salt/kgwater, between about 100 g salt/kg water and about 500 g salt/kg water,between about 500 g salt/kg water and about 1,000 g salt/kg water, orbetween about 1,000 g salt/kg water and about 2,000 g salt/kg water.However, the disclosure is not so limited and the brine may have adifferent concentration of salt.

The nanoparticles may include nanoparticles that exhibit a negativelycharged core, nanoparticles that include a negatively charged surface,nanoparticles including anionic functional groups formulated andconfigured to interact with hydrocarbons in a material, such as withactive sites of a subterranean formation or in oil sands, andcombinations thereof. By way of nonlimiting example, the nanoparticlesmay include silica nanoparticles, functionalized silica nanoparticles,nanoparticles including a core comprising polyoctahedral silsesquioxane(POSS), metal nanoparticles (e.g., nanoparticles of one or more of iron,titanium, germanium, tin, lead, zirconium, ruthenium, nickel, cobalt,etc.), metal oxide nanoparticles (e.g., nanoparticles of one or more ofoxides of iron, titanium, germanium, tin, lead, zirconium, ruthenium,nickel, cobalt, etc.), carbon nanoparticles (e.g., carbon nanotubes(e.g., single-walled carbon nanotubes (SWCNTs), multi-walled carbonnanotubes (MWCNTs), fullerenes, carbon nanodiamonds, graphene, grapheneoxide)), aluminum silicate nanoparticles, alumina modified silicananoparticles (which may also be referred to as aluminate modifiedsilica nanoparticles), metal oxide modified silica nanoparticles,functionalized alumina modified silica nanoparticles, functionalizedmetal oxide silica nanoparticles, and combinations thereof. In someembodiments, the nanoparticles include silica nanoparticles, aluminamodified silica nanoparticles, metal oxide modified silicananoparticles, aluminum silicate nanoparticles (which may also bereferred to as aluminosilicate nanoparticles), and combinations thereof.The aluminum silicate nanoparticles may include Al₂SiO₅ (Al₂O₃.SiO₂),Al₂Si₂O₅(OH)₅ (Al₂O₃.2SiO₂.2H2O), Al₂Si₂O₇ (Al₂O₃.2SiO₂), Al₆SiO₁₃(3AlO₃.2SiO₂), Al₄SiO₈ (2Al₂O₃.SiO₂), or combinations thereof.Accordingly, in some embodiments, the nanoparticles may comprise atomsof aluminum, silicon, and oxygen.

In some embodiments, the nanoparticles comprise alumina modified silicananoparticles. FIG. 1A is a simplified schematic of an alumina modifiedsilica nanoparticle 150. The alumina modified silica nanoparticle 150includes a core 152 comprising silica. Silicon atoms may be bonded tosurfaces 154 of the core 152. The surface 154 may include alumina. Forexample, the silicon atoms on the surface 154 may be bonded to oxygenatoms, which in turn, may be bonded to aluminum atoms. In someembodiments, the silicon atoms at the surface 154 may include terminalhydroxyl groups and the aluminum atoms at the surface 154 may includenegatively charged terminal hydroxyl groups.

In some embodiments, the nanoparticles comprise metal oxide modifiedsilica nanoparticles. FIG. 1B is a simplified schematic of a metal oxidemodified silica nanoparticle 160. The metal oxide modified silicananoparticle 160 may be substantially similar to the alumina modifiedsilica nanoparticle 150 (FIG. 1A), except that the surface 154 may notinclude aluminum atoms, but may include other metal atoms, representedas a “M” in FIG. 1B. The other metal atoms may include, for example,titanium, zirconium, gallium, boron, iron, indium, hafnium, anothermetal, or combinations thereof.

In some embodiments, the nanoparticles comprise functionalized aluminamodified silica nanoparticles. FIG. 1C is a simplified schematic of afunctionalized alumina modified silica nanoparticle 170. Thefunctionalized alumina modified silica nanoparticle 170 may be similarto the alumina modified silica nanoparticle 150 (FIG. 1A), except thatsilicon atoms on the surface 154 may not include terminal hydroxylgroups, but may include other terminal functional groups, represented asan “R” in FIG. 1C. The functional groups may include, for example, analkyl silane, an aryl silane, (3-aminopropyl)triethoxysilane (APTES),(3-glycidylkoxypropyl)trimethoxysilane (also referred to as glymosilane), polyethylene glycol (PEG), one or more carbohydrates (e.g., agroup including carbon, hydrogen, and oxygen atoms), or other functionalgroups.

In some embodiments, the nanoparticles may be functionalized by bondinga functional group R to silicon atoms to form functionalizednanoparticles, as described in U.S. patent application Ser. No.15/940,459, titled “COMPOSITIONS OF MATTER COMPRISING SUSPENEDNANOPARTICLES AND RELATED METHODS,” the disclosure of which is herebyincorporated herein in its entirety by this reference. The functionalgroup may be an organosilicon functional group having a silicon atom andat least one organic moiety connected by a Si—C bond. The functionalgroup R may provide stabilization to the functionalized nanoparticles,and may make the functionalized nanoparticles relatively more physicallystable in the suspension. By way of nonlimiting example, the functionalgroup R may be formed from any of the compounds listed and shown inTable I or any of the classes of compounds listed in Table II.

TABLE I Name MW Structure (3-glycidyloxy- propyl) trimethoxy- silane(also known as GLYMO) 236

3-(trimethoxy- silyl)propyl acrylate 234

3-(trimethoxy- silyl)propyl methacrylate 248

trimethoxy (octadecyl)silane 375

hexadecyl- trimethoxysilane 347

trimethoxy (7-octen-1- yl)silane 232

TABLE II Description Structure methoxy PEG silane

carboxylic acid terminated PEG silane

amine terminated PEG silane

O-[methoxy(polyethylene oxide)]-n- triethoxysilylpropyl)carbamate

2-[methoxypoly(ethylenoxy)⁶⁻⁹ propyl]dimethylmethoxysilane

2-[methoxy(polyethyleneoxy)⁶⁻⁹ propyl]trichlorosilane

2-[methoxypoly(ethylenoxy)⁶⁻⁹ propyl]dimethylchlorosilane

[hydroxy(polyethyleneoxy) propyl]triethoxysilane

In some embodiments, the functional group R may include a glucose,sucrose-, or fructose-modified silane or siloxane. The functional groupR may include an alkoxy group (i.e., an alkyl group singularly bonded tooxygen) bonded to silicon. The functional group R may be hydrophilic,which may improve the suspension of the functionalized nanoparticles inthe suspension and/or carrier fluid. Each functionalized nanoparticlemay include one or more functional groups R bonded thereto. The degreeof stability of the functionalized nanoparticles may increase with anincreasing number of functional groups R.

In some embodiments, the nanoparticles comprise functionalized metaloxide modified silica nanoparticles. In some such embodiments, thefunctionalized metal oxide modified silica nanoparticles may besubstantially the same as the alumina modified silica nanoparticles,except that the aluminum atoms may be replaced with one or more metalatoms M, as described above.

Accordingly, the nanoparticles described herein may be functionalizedwith one or more of the functional groups described herein.

In some embodiments, the nanoparticles comprise a first group ofnanoparticles comprising at least one of silica nanoparticles, and asecond group of nanoparticles comprising one or more of aluminumsilicate nanoparticle, alumina modified silica nanoparticles, and metaloxide modified silica nanoparticles, functionalized alumina modifiedsilica nanoparticles, or functionalized metal oxide modified silicananoparticles. In some embodiments, the nanoparticles comprise silicananoparticles and aluminum silicate nanoparticles. In other embodiments,the nanoparticles comprise silica nanoparticles and alumina modifiedsilica nanoparticles. In yet other embodiments, the nanoparticlescomprise alumina modified silica nanoparticles and aluminum silicatenanoparticles. In some embodiments, the nanoparticles further comprisemetal oxide modified silica nanoparticles. The nanoparticles may befunctionalized.

In some embodiments, surfaces of the nanoparticles may be functionalizedwith an alkyl group, an alkenyl group, an alkynyl group, a hydroxylgroup, an organohalide group, a halide group, a carbonyl group, an aminegroup, an organosulfur group, an epoxy group, and a polyamine group, anaryl group (e.g., an aralkyl or an alkaryl group), a carbonyl group (acarbonyl group (—C═O)), such as a ketone, an aldehyde, a carboxylate(−COO⁻) group, an amine group, a thiol group, a phosphate (—PO₄ ³⁻)group, another functional group, or combinations thereof.

In some embodiments, surfaces of the nanoparticles may be functionalizedwith functional groups formulated and configured to provide a negativecharge to the surface of the nanoparticles (e.g., anionic functionalgroups). By way of nonlimiting example, the anionic functional groupsmay include one or more of hydroxyl (—OH⁻) groups, carboxylate (—COO⁻)groups, sulfonate (—SO₃ ⁻) groups, phosphate (—PO₄ ³⁻) groups, etc. Insome embodiments, the functional groups may be formulated and configuredto form nanoparticles formulated and configured to form a suspensionhaving a negative zeta potential when mixed with the carrier fluid.

The functional group may be bonded directly to the core of thenanoparticle. In other embodiments, the functional group may be bondedto the core of the nanoparticle through one or more bridge groups (e.g.,an R group, such as an alkyl group, an alkenyl group, an alkynyl group,a carbonyl group, an amine group, another group, or combinationsthereof).

In some embodiments, at least some of the nanoparticles may befunctionalized with at least a first type of functional group and atleast some of the nanoparticles may be functionalized with at least asecond type of functional group. By way of nonlimiting example, in someembodiments, at least some of the nanoparticles may be functionalizedwith sulfonate functional groups and at least some of the nanoparticlesmay be functionalized with carboxylate functional groups. As anotherexample, at least some of the nanoparticles may be functionalized withphosphate groups and at least some of the nanoparticles may befunctionalized with sulfonate groups or carboxylate groups. In yet otherembodiments, at least some of the nanoparticles are functionalized withsulfonate groups, at least some of the nanoparticles are functionalizedwith phosphate groups, and at least some of the nanoparticles arefunctionalized with carboxylate groups. In other embodiments, at leastsome of the nanoparticles may not be functionalized and at least some ofthe nanoparticles may be functionalized. In further embodiments, atleast some of the nanoparticles may be functionalized with for example,an alkyl silane, an aryl silane, APTES,(3-glycidylkoxypropyl)trimethoxysilane, PEG, one or more carbohydrates,or other functional groups and at least other of the nanopartilces maybe functionalized with another of alkyl silane, APTES,(3-glycidylkoxypropyl)trimethoxysilane, PEG, one or more carbohydrates,or other functional groups.

The nanoparticles may include a hydrophobic coating on surfaces thereof(e.g., silica nanoparticles having a surface modified with a reactiveepoxy silane), a hydrophilic coating on surfaces thereof (e.g.,hydrophilic fumed silica, hydrophilic fumed silica includingfunctionalized surfaces, or a combination thereof), or a combinationthereof.

The nanoparticles may have a spherical shape, a cylindrical shape, aplate shape, or another suitable shape. In some embodiments, thenanoparticles have a spherical shape.

The nanoparticles may have a size between about 5 nm and about 100 nm.In some embodiments, the nanoparticles have a size between about 5 nmand about 10 nm, between about 10 nm and about 15 nm, between about 15nm and about 20 nm, between about 20 nm and about 50 nm, or betweenabout 50 nm and about 100 nm. The size of the nanoparticles may beselected to be less than a pore size of a subterranean formation inwhich the nanoparticles are to be introduced, an open pore dimensionbetween grains of oil sands, etc. In some embodiments, the nanoparticleshave a size less than about 100 nm, less than about 50 nm, less thanabout 20 nm, less than about 15 nm, less than about 10 nm, or even lessthan about 5 nm. The nanoparticles may be monodisperse, wherein each ofthe nanoparticles exhibit substantially the same size and shape, or maybe polydisperse, wherein the nanoparticles include a range of sizesand/or shapes.

A concentration of the nanoparticles in the suspension may be betweenabout 100 ppm and about 5,000 ppm, such as between about 100 ppm andabout 200 ppm, between about 200 ppm and about 500 ppm, between about500 ppm and about 1,000 ppm, between about 1,000 ppm and about 2,500ppm, or between about 2,500 ppm and about 5,000 ppm. However, thedisclosure is not so limited and the concentration of the nanoparticlesin the suspension may be lower or higher depending on a particularapplication.

A pH of the suspension may be between about 3.0 and about 12.0. In someembodiments, the suspension may exhibit a basic pH, such as a pH greaterthan about 9.0, greater than about 10.0, or even greater than about11.0. In other embodiments, the suspension may exhibit a pH betweenabout 7.0 and about 9.0, such as about 8.0. In other embodiments, thesuspension may exhibit an acidic pH, such as a pH between about 3.0 andabout 7.0, such as between about 3.0 and about 5.0, or between about 5.0and about 7.0. In some embodiments, the pH of the suspension may beabout 3.0. However, the disclosure is not so limited and the suspensionmay exhibit a different pH.

In some embodiments, act 102 may be performed after primary hydrocarbonrecovery and secondary hydrocarbon recovery. By way of nonlimitingexample, act 102 may be performed after performing one or more of waterflooding, steam flooding (e.g., steam assisted gravity drainage (SAGD),cyclic steam stimulation (CSS), vapor extraction, etc.), or one or moreother forms of secondary hydrocarbon recovery.

Act 104 may include a flooding process including introducing the firstfluid to the material and contacting surfaces of the material with thenanoparticles to adsorb the nanoparticles on surfaces of the material.Without wishing to be bound by any particular theory, it is believedthat the nanoparticles interact with active sites of the material (e.g.,subterranean formation, oil sands, bitumen, etc.) and form a monolayerof nanoparticles thereon. It is believed that the nanoparticles mayremove a hydrocarbon film from surfaces of the material. In someembodiments, the nanoparticles may be formulated and configured tointeract with active sites of surfaces of the material. By way ofnonlimiting example, the nanoparticles may include amine functionalgroups. The nanoparticles may adhere to and interact with (e.g., bondwith) surfaces of the material.

In some embodiments, act 104 may be performed after primary hydrocarbonrecovery and secondary hydrocarbon recovery, such as one or more ofwater flooding and one or more other forms of secondary hydrocarbonrecovery. In other embodiments, act 104 includes mixing nanoparticleswith water used during water flooding processes. In some suchembodiments, the nanoparticles in the water flooding solution orsuspension may contact and adhere to surfaces of the material(subterranean formation, oil sands, bitumen, etc.). In some suchembodiments, a first portion of water flooding may be performed withoutthe nanoparticles and a second portion thereof may be performed with thenanoparticles. In yet other embodiments, act 104 may be performedimmediately after primary after primary hydrocarbon recovery, withoutperforming water flooding.

Act 106 includes mixing at least one charged (e.g., anionic) surfactantwith another carrier fluid to form a second fluid to be introduced tothe material (e.g., injected into the subterranean formation, introducedto oil sands, bitumen, etc.). The another carrier fluid may includewater, brine, seawater, condensate, steam, etc., or combinationsthereof. In some embodiments, the another carrier fluid includes brine.In some embodiments, the another carrier fluid comprises the samematerial as the carrier fluid used in act 102.

The charged surfactant may comprise an anionic surfactant including anysurfactant formulated and configured to reduce an interfacial tensionbetween a hydrocarbon phase and an aqueous phase and mobilize thehydrocarbon phase within the subterranean formation. The anionicsurfactant may include at least one anionic surfactant selected from thegroup consisting of sulfonates (e.g., including one or more sulfonate(—SO₃ ⁻) groups), sulfates (e.g., including one or more sulfate (—SO₄²⁻) groups, carboxylates (e.g., including one or more carboxylategroups), phosphates (e.g., including one or more phosphate (—PO₄ ³⁻)groups), or combinations thereof.

By way of nonlimiting example, the anionic surfactant may include asodium alkyl sulfate (e.g., sodium dodecyl sulfate (SDS)), sodium alkylaryl sulfonate, sodium dodecylbenzenesulfonate (C₁₈H₂₉NaO₃S), sodiumlaureth sulfate (CH₃(CH₂)₁₀CH₂(OCH₂CH₂)_(n)OSO₃Na), sodium stearate(C₁₈H₃₅NaO₂), sodium laurate (CH₃(CH₂)₁₀CO₂Na), sulfated alkanolamides,a benzyl dodecane sulfonate sodium salt, a glycolic acid ethoxylatelauryl ether, sulfo-caborboxylic compounds (e.g., sodium laurylsulfoacetate, dioctyl sulfosuccinate, etc.), organo phosohoredsurfactants, sarcosides or alkyl amino acids, ammonium lauryl sulfate,sodium phosphates, phosphate esters, internal olefin surfactants,alcohol alkoxy sulfates, alkyl alkoxy carboxylates, other anionicsurfactants, and combinations thereof. In some embodiments, the anionicsurfactant comprises a carboxylated surfactant (e.g., sodium stearate,sodium lauroyl sarcosinate, etc.).

In some embodiments, the anionic surfactants may include the same groupsas the functional groups of the nanoparticles described above withreference to act 102. For example, the where the anionic surfactantincludes sulfonates, the nanoparticles may include sulfonate functionalgroups. In embodiments where the anionic surfactant includescarboxylates or phosphates, the nanoparticles may include carboxylate orphosphate functional groups, respectively. In some such embodiments, atleast some of the anionic surfactants may include the same groups as thefunctional groups adhered to the surfaces of the material (e.g.,subterranean formation, oil sands, bitumen, etc.) during act 104.

A concentration of the anionic surfactant in the carrier fluid may bebetween about 10 ppm and about 50,000 ppm, such as between about 10 ppmand about 50 ppm, between about 50 ppm and about 100 ppm, between about100 ppm and about 200 ppm, between about 200 ppm and about 500 ppm,between about 500 ppm and about 1,000 ppm, between about 1,000 ppm andabout 3,000 ppm, between about 3,000 ppm and about 5,000 ppm, betweenabout 5,000 ppm and about 10,000 ppm, between about 10,000 ppm and about30,000 ppm, or between about 30,000 ppm and about 50,000 ppm. However,the disclosure is not so limited and the concentration of the anionicsurfactant may be different than those described. In some embodiments, aconcentration of the anionic surfactant may be greater than a criticalmicelle concentration (CMC, a concentration of surfactants above whichmicelles form and additional surfactants added to the system formmicelles). It is believed that a concentration of surfactants greaterthan the CMC may improve hydrocarbon recovery from the material. Withoutwishing to be bound by any particular theory, it is believed that abovethe CMC, a microemulsion may form between an aqueous phase and thehydrocarbon phase. The microemulsion may reduce an interfacial tensionbetween the hydrocarbon phase and the aqueous phase and the solid phaseof the subterranean formation. In addition, a concentration ofsurfactants greater than the CMC may increase hydrocarbon recovery fromthe material since, in some embodiments, at least some of the surfactantmay be adsorbed onto surfaces of the material.

In some embodiments, the second fluid may not include nanoparticles. Inother embodiments, the second fluid may include both the anionicsurfactant and nanoparticles. In some such embodiments, thenanoparticles may have a negatively charged surface. By way ofnonlimiting example, the second fluid may include silica nanoparticles,aluminum silicate nanoparticles, alumina modified silica nanoparticles,metal oxide modified silica nanoparticles, functionalized aluminamodified silica nanoparticles, functionalized metal oxide modifiedsilica nanoparticles, POSS nanoparticles, carbon nanoparticles, metalnanoparticles, metal oxide nanoparticles, or combinations thereof. Insome embodiments, the nanoparticles comprise silica nanoparticles.

The nanoparticles may have the same size and shape as the nanoparticlesdescribed above with reference to the nanoparticles in the first fluid.In some embodiments, the nanoparticles in the second fluid are the sameas the nanoparticles in the first fluid. In other embodiments, thenanoparticles in the first fluid and the nanoparticles in the secondfluid are different. By way of nonlimiting example, the nanoparticles inthe first fluid may be formulated and configured to interact with activesites on surfaces of the material (e.g., the subterranean formation, oilsands, bitumen, etc.). By way of nonlimiting example, where the materialincludes active sites including exposed hydroxyl groups, thenanoparticles in the first fluid may be formulated and configured tointeract with the exposed hydroxyl groups thereof. In some suchembodiments, the nanoparticles of the first fluid may include hydroxylgroups, amine groups, carboxylate groups, isocyanate groups, anotherfunctional group, sulfonate functional groups, phosphate functionalgroups, one or more of the R groups described above, and combinationsthereof. The nanoparticles of the second fluid may include nanoparticleshaving a negatively charged core, exposed anionic functional groups, orboth. In some embodiments, the nanoparticles of the second fluid includefunctional groups that are the same as the groups of the surfactant(e.g., where the surfactant comprises sulfonates, carboxylates, orphosphates, the nanoparticles may respectively include sulfonate,carboxylate, or phosphate functional groups.

In some embodiments, the nanoparticles in the second fluid have adifferent size (e.g., diameter) than the nanoparticles in the firstfluid. By way of nonlimiting example, the nanoparticles of the secondfluid may exhibit a lower mean diameter than the nanoparticles of thefirst fluid. In other embodiments, the nanoparticles of the second fluidmay exhibit a greater mean diameter than the nanoparticles of the firstfluid.

In some embodiments, a concentration of the surfactant in the secondfluid may be greater than a concentration of the nanoparticles in thesecond fluid. By way of nonlimiting example, the concentration ofsurfactant in the second fluid may be between about 500 ppm and about5,000 ppm and a concentration of the nanoparticles in the second fluidmay be between about 100 ppm and about 2,000 ppm. In some embodiments,the concentration of the surfactant may be about 1,500 ppm and theconcentration of the nanoparticles may be about 200 ppm.

In some embodiments, a ratio of surfactant to nanoparticles (e.g., aconcentration of surfactant divided by a concentration of nanoparticles)in the second fluid may be greater than about 1.0. By way of nonlimitingexample, the ratio of surfactant to nanoparticles in the second fluidmay be greater than about 1.0, greater than about 1.5, greater thanabout 2.0, greater than about 2.5, greater than about 3.0, greater thanabout 4.0, greater than about 5.0, or even greater than about 10.0.

Act 108 includes introducing the second fluid into the material (e.g.,the subterranean formation, oil sands, bitumen, etc.). An amount ofanionic surfactant that is lost due to adsorption on surfaces of thematerial may be reduced because of the nanoparticles already attached tothe active sites thereof in act 104. Without wishing to be bound by anyparticular theory, it is believed that introducing the nanoparticlesduring act 104 reduces a number of active sites in the material that mayotherwise interact with the anionic surfactant such that a lesser amountof the anionic surfactant is lost caused by adsorption to surfaces ofthe material. Stated another way, introducing the nanoparticles into thematerial and adhering the nanoparticles to surfaces thereof prior tointroducing the surfactant into the material may reduce an amount ofsurfactant lost in the material and may increase an effectiveness of thesurfactant (e.g., by increased hydrocarbon recovery).

In some embodiments, where the second fluid includes nanoparticles, thenanoparticles of the second fluid may be formulated and configured toreduce a degree of interaction between the anionic surfactants and theactive sites on surfaces of the material. Without wishing to be bound byany particular theory, it is believed that the nanoparticles including anegatively charged core, anionic functional groups, or both may interactwith the anionic surfactant in the carrier fluid to facilitate transportof the anionic surfactant deeper into the material while reducing anadsorption of the anionic surfactant onto surfaces of the material. Itis believed that the nanoparticles introduced to the material during act104 may interact with the active sites on surfaces of the material,reducing a likelihood of adsorption of the surfactant in the secondfluid with the active sites. In addition, it is believed that cations inthe carrier fluid (e.g., Ca²⁺ and Mg²⁺ when the carrier fluid comprisesbrine) interact with any nanoparticles present in the second fluid andform a so-called “shell” around the nanoparticles due to ion-ioninteractions between the negative charges associated with thenanoparticles and the cations in the carrier fluid. The anionicsurfactants may be attracted to the positively charged shell of cationssurrounding the nanoparticles in the second fluid and may form anothershell around the cations surrounding the nanoparticles. Accordingly, theanionic heads of the surfactant may be oriented toward the shell of thenanoparticle and the tail portion of the surfactant may be oriented awayfrom the nanoparticles. The tail portion of the anionic surfactant mayinclude, for example, alkyl groups. Within the material, the tailportion of the anionic surfactant may be oriented toward the surfacesthereof while the anionic head portion remains directed toward thepositively charged shell surrounding the nanoparticles. Accordingly, itmay be more likely for the anionic heads of the anionic surfactants tointeract with the nanoparticles than with the active sites of thematerial. In addition, due to the size of the nanoparticles, thenanoparticles may exhibit a substantially greater surface area than asurface area of the active sites of the material.

Act 110 includes flowing (e.g., driving, sweeping, forcing, etc.) thehydrocarbons from the material to a location away from the material(e.g., to a location above the subterranean formation). The surfactantmay reduce an interfacial tension between the hydrocarbon phase and anaqueous phase. Accordingly, in some embodiments, the surfactant mayincrease a mobility of hydrocarbons within the subterranean formationand the hydrocarbons may be transported to above the subterraneanformation.

Although FIG. 1 has been described as including sequentially introducinga first fluid and a second fluid to the material, the disclosure is notso limited. In other embodiments, a suspension comprising both thenanoparticles and the anionic surfactant may be introduced to a materialsimultaneously. FIG. 2 is a simplified flow diagram illustrating amethod 200 of obtaining a hydrocarbon material from a material (e.g., asubterranean formation, oil sands, bitumen, etc.), according toembodiments of the disclosure. The method 200 includes act 202 includingmixing nanoparticles and at least one charged (e.g., anionic) surfactantwith a carrier fluid to form a suspension including the nanoparticlesand the at least one anionic surfactant; act 204 including a floodingprocess including introducing the suspension to a material (e.g., into asubterranean formation, to oil sands, bitumen, etc.) and contactingsurfaces of the material with the nanoparticles to adsorb thenanoparticles on surfaces thereof; and act 206 including flowing (e.g.,driving, sweeping, forcing, etc.) the hydrocarbons from the material toa location away from the material (e.g., to a location above thesubterranean formation).

Act 202 includes mixing nanoparticles and at least one charged (e.g.,anionic) surfactant with a carrier fluid to form a suspension includingthe nanoparticles and the at least one anionic surfactant. The anionicsurfactant may include the same anionic surfactants described above withreference to FIG. 1.

The nanoparticles may include the same nanoparticles as those describedabove with reference to FIG. 1. For example, the nanoparticles mayexhibit a negatively charged core, may include a negatively chargedsurface, may include anionic functional groups formulated and configuredto interact with active sites of a material (e.g., a subterraneanformation, oil sands, bitumen, etc.), and combinations thereof. By wayof nonlimiting example, the nanoparticles may include silicananoparticles, nanoparticles including a core comprising polyoctahedralsilsesquioxane (POSS), metal oxide nanoparticles (e.g., nanoparticles ofone or more of oxides of iron, titanium, germanium, tin, lead,zirconium, ruthenium, nickel, cobalt, etc.), carbon nanoparticles (e.g.,carbon nanotubes (e.g., single-walled carbon nanotubes (SWCNTs),multi-walled carbon nanotubes (MWCNTs), fullerenes, carbon nanodiamonds,graphene, graphene oxide), alumina modified silica nanoparticles, metaloxide modified silica nanoparticles, aluminum silicate nanoparticles,and combinations thereof. In some embodiments, the nanoparticlescomprise or include silica nanoparticles, functionalized silicananoparticles, alumina modified silica nanoparticles, functionalizedalumina modified silica nanoparticles, functionalized metal oxidemodified silica nanoparticles, aluminum silicate nanoparticles, orcombinations thereof. The nanoparticles may include one or morefunctional groups as described above with reference to FIG. 1.

Act 204 may include a flooding process including introducing thesuspension to a material (e.g., into a subterranean formation, oilsands, bitumen, etc.) and contacting surfaces thereof with thenanoparticles to adsorb the nanoparticles on surfaces of the material.Exposing the material to the suspension including both the nanoparticlesand the anionic surfactant may substantially reduce an amount ofsurfactant losses due to adsorption of the anionic surfactant ontosurfaces thereof.

Without wishing to be bound by any particular theory, it is believedthat introducing nanoparticles including a negatively charged surface(e.g., silica nanoparticles) to the material and exposing the materialto anionic surfactants simultaneously alters a wettability of thematerial surface (e.g., formation surfaces). It is believed that thenanoparticles alter a wettability of the material surface. The alteredwettability of the material surface may substantially reduce an amountof surfactant that interacts with (e.g., adsorbs onto) surfaces of thematerial. Accordingly, more of the anionic surfactant may be present ata hydrocarbon/aqueous interface, reducing an interfacial tensiontherebetween and improving a flowability of hydrocarbons from thematerial.

Act 206 may include flowing (e.g., driving, sweeping, forcing, etc.) thehydrocarbons from the material (e.g., subterranean formation, oil sands,bitumen, etc.) to a location away from the material (e.g., to a locationabove the subterranean formation). In some embodiments, act 206 may besubstantially the same as act 110 described above with reference to FIG.1.

In some embodiments, the mixture of nanoparticles and the anionicsurfactant may be stable (e.g., may not agglomerate) at temperatures ashigh as about 80° C. and at salinities that may be encountered duringwellbore operations. Without wishing to be bound by any particulartheory, it is believed that the unique combination of nanoparticles andanionic surfactants facilitate the stability of the suspension and useof the suspension in the subterranean formation to increase hydrocarbonrecovery therefrom. In some embodiments, the surfactant may include asurfactant in addition to, or other than SDS, since in some instancesSDS may not exhibit effectiveness in brine and temperatures greater thanabout 20° C. In some embodiments, the surfactant comprises acarboxylated surfactant. In some embodiments, the carboxylatedsurfactant used in combination with the nanoparticles may facilitate anincrease in hydrocarbon recovery from the material. In some embodiments,the surfactant includes carboxylated surfactants and sulfonatedsurfactants. It is believed that carboxylated surfactants enhancehydrocarbon recovery and sulfonated surfactants increase a temperaturestability of the mixture including the surfactants.

Without wishing to be bound by any particular theory, it is believedthat the combination of nanoparticles and surfactant in the material(e.g., subterranean formation, oil sands, etc.) exhibit synergisticproperties. It is believed that the nanoparticles form a wedge betweenhydrocarbons and the surface of the material. The nanoparticles maygenerate a disjoining pressure on the three-phase contact point (i.e.,between the aqueous phase, the hydrocarbon phase, and the solid phase ofthe material). The disjoining pressure may mobilize the hydrocarbons.Since the nanoparticles include a negative charge (similar to thenegative charge of the anionic surfactant), the nanoparticles, ratherthan the surfactant, may interact with the active sites of the materialto reduce a loss of surfactant caused by adsorption. As the hydrocarbonsare mobilized from surfaces of the material, the surfactant may interactwith the hydrocarbons and reduce an interfacial tension between thehydrocarbon phase and the aqueous phase, increasing a mobility of thehydrocarbons.

EXAMPLES Example 1

An amount of enhanced hydrocarbon recovery (e.g., enhanced oil recovery(EOR)) with suspensions comprising only nanoparticles, suspensionscomprising only surfactants, and suspensions comprising nanoparticlesand surfactants was compared. Table III below includes a composition ofeach suspension tested and includes an amount of hydrocarbon recoveryfor each suspension.

TABLE III Pore Permeability Temp. % Sample Suspension Volume Φ (k) (°C.) S_(o) ORWF % EOR 1 0.5 wt % silica 38.1 22.3 1513 25 0.88 57.1 16-19nanoparticles 2 0.5 wt % silica 50.7 32.1 5228 80 0.47 53.8 0.98nanoparticles 3 0.3 wt. % 44.8 28.1 1921 70 0.63 69.1 1.3 surfacefunctionalized silica, pH 3 4 0.2 wt. % 34.5 21.9 987 80 0.76 49.4 0.5surface modified silica 5 1500 ppm 33.2 21.0 975 80 0.75 52.8 5.9surfactant 6 200 ppm 32.0 20.3 647 80 0.75 51.2 10.0 silicananoparticles and 1,500 ppm surfactant

In Table III, Φ represents a porosity of the sample (e.g., the material,such as a subterranean formation), S_(o) is the initial oil saturationin the sample, % ORWF is the percent hydrocarbon recovery during waterflooding, and % EOR is the percent of enhanced hydrocarbon recoveryafter flooding with the suspension.

In each sample, an initial water flooding process was performed on thesample to recover an initial amount of hydrocarbons therefrom, theamount of which recovery is indicated in the column labeled “% ORWF.”Thereafter, each sample was flooded with the indicated suspension tofurther enhance hydrocarbon recovery therefrom. The additional amount ofhydrocarbons recovered from each sample responsive to flooding with thesuspension is shown in the column labeled “% EOR.”

With reference to Table III, an amount of enhanced hydrocarbon recoverydramatically decreases when the nanoparticles in the suspension areexposed to a temperature greater than about 25° C. For example, at atemperature of about 25° C., silica nanoparticles enhance hydrocarbonrecovery by between about 16% and about 19%. By way of contrast,hydrocarbon recovery is enhanced by only about 0.98%, about 1.3%, orabout 0.5% when the silica nanoparticles are exposed to a temperature ofabout 80° C. or about 70° C.

FIG. 3A is a graph illustrating a percent of hydrocarbon recovery as afunction of a volume of fluid introduced into a core sample in alaboratory, the core sample representative of a subterranean formation,wherein the core sample had a temperature of about 70° C., a temperaturethat may be encountered in a subterranean formation and/or duringhydrocarbon recovery from a material. An initial water flooding processresulted in about 65% hydrocarbon recovery. Thereafter, flooding with asolution including about 500 ppm of silica nanoparticles increasedhydrocarbon recovery by about 0.50% and flooding with a solutionincluding about 2,500 ppm of the silica nanoparticles further increasedan amount of hydrocarbon recovery by another about 0.20%. An additionalabout 0.62% of hydrocarbons was recovered responsive to shutting thecore sample in for between about 8 hours and about 12 hours.

FIG. 3B is a graph illustrating a percent of hydrocarbon recovery as afunction of fluid introduced into a core sample in a laboratory, whereinthe core sample had a temperature of about 80° C. An initial floodingwith artificial seawater (ASW) resulted in hydrocarbon recovery of about50%. Thereafter, exposing the sample to a flooding solution comprisingsilica nanoparticles increased the hydrocarbon recovery by another about0.5%. Comparing FIG. 3A and FIG. 3B, an amount of hydrocarbon recoveryusing water flooding or flooding with artificial seawater decreased withan increasing temperature of the core sample.

Referring again to Table III, an amount of hydrocarbon recovery floodingwith a suspension including surfactants (Sample 5) was compared to anamount of hydrocarbon recovery responsive flooding with a suspensioncomprising the surfactant and silica nanoparticles (Sample 6).

FIG. 3C graphically compares the results of Sample 5 and Sample 6. Asshown in the graph, an amount of hydrocarbon recovery was increased byabout 5.9% responsive to flooding with an additional fluid comprisingsurfactants, even when the sample was maintained at a temperature ofabout 80° C. Flooding a sample with a flooding suspension comprising thesurfactant and silica nanoparticles increased hydrocarbon recovery fromthe sample by about 10.0%. Accordingly, it appears that the use of thesurfactant and the nanoparticles in combination has a synergistic effecton hydrocarbon recovery from a hydrocarbon-containing material andappears to increase an amount of hydrocarbon recovery more than theindividual sum of hydrocarbon recovery by flooding with onlynanoparticles and flooding with only surfactant.

Example 2

An amount of enhanced hydrocarbon recovery from a sample responsive tosequential flooding with several different flooding solutions wasmeasured. The sample exhibited a pore volume of about 35.1, a porosityof about 22.2, a permeability of about 472, a temperature of about 60°C., and an initial oil saturation of about 0.60.

The sample was first exposed to artificial seawater, resulting inrecovery of about 77.4% of the hydrocarbons from the sample. Thereafterthe sample was exposed to a solution comprising about 5,000 ppm ofsilica nanoparticles, followed by flooding with the artificial seawater.Thereafter, the artificial seawater remained in the sample overnight(for between about 8 hours and about 12 hours). Then, the sample wasflooded with a suspension including about 3,000 ppm silica nanoparticlesand about 2,000 ppm of sodium dodecyl sulfate (SDS), followed byflooding with a solution comprising about 2,000 ppm SDS, and thenflooding with a suspension comprising about 3,000 ppm silicananoparticles and 2,000 ppm SDS. Table IV below shows the amount ofhydrocarbon recovery responsive to the different flooding operations.

TABLE IV % Flooding Flooding Fluid Recovery 1 ASW 77.4 2 5,000 ppmsilica nanoparticles 0.8 3 ASW 1.6 4 Shut in 1.4 5 3,000 ppm silicananoparticles + 7.9 2,000 ppm SDS 6 2,000 ppm SDS 0.3 7 3,000 ppm silicananoparticles + 0.2 2,000 ppm SDS

Referring to Table IV, an amount of hydrocarbon recovery from the sampleincreased by about 7.9% responsive to exposure to the floodingsuspension comprising the silica nanoparticles and the SDS surfactantafter the sample had previously been exposed to a flooding suspensioncomprising silica nanoparticles. FIG. 4 is a graphical representation ofan amount of hydrocarbon recovery from the sample responsive to each ofthe flooding operations.

Example 3

An amount of enhanced hydrocarbon recovery from a sample responsive tosequential exposure to several different flooding solutions wasmeasured. The sample exhibited a pore volume of about 34.4, a porosityof about 22.0, a permeability of about 1613, a temperature of about 60°C., and an initial oil saturation of about 0.77.

The sample was first flooded with a solution of artificial seawater,resulting in recovery of about 50.1% of the hydrocarbons from thesample. Thereafter the sample was flooded with a solution comprisingabout 2,000 ppm of SDS. Thereafter, the sample was flooded with asuspension comprising 3,000 ppm silica nanoparticles and 2,000 ppm SDS,then flooded with a suspension comprising 20,000 ppm silicananoparticles and 2,000 ppm SDS, and then flooded with a suspensioncomprising 10,000 ppm silica nanoparticles and 2,000 ppm SDS. Table Vbelow shows the amount of hydrocarbon recovery responsive to thedifferent flooding operations.

TABLE V % Flooding Flooding Fluid Recovery 1 ASW 50.1 2 2,000 ppm SDS3.7 3 2,000 ppm SDS + 3,000 ppm 0.2 silica nanoparticles 4 2,000 ppmSDS + 20,000 ppm 0.1 silica nanoparticles 5 2,000 ppm SDS + 10,000 ppm0.1 silica nanoparticles

FIG. 5 is a graphical representation of the amount of hydrocarbonrecovery from the sample responsive to each flooding operation. In someembodiments, the amount of hydrocarbon recovery does not appear toincrease as significantly when the sample is exposed to the SDSsurfactant prior to exposure to the nanoparticles.

Example 4

Adsorption of surfactants on surfaces of a subterranean formation sampleand adsorption of silica nanoparticle on the surfaces of the sample weremeasured. The results are shown in Table VI below.

TABLE VI Absorption (mg/g Flooding Fluid sample) Silica nanoparticles inartificial seawater 0.30 Carboxylated surfactant in distilled water 0.08Carboxylated surfactant in artificial seawater 0.81 Carboxylatedsurfactant after exposure of 0.26 sample to silica nanoparticles inartificial seawater

Accordingly, an amount of silica nanoparticles adsorbed onto surfaces ofthe sample was greater when the carrier fluid comprised artificialseawater than when the carrier fluid comprised distilled water. Thus, aloss of nanoparticles due to adsorption increased with increasingsalinity of the carrier fluid. In an artificial seawater carrier fluid,the SDS surfactant exhibited an adsorption of about 0.81 mg surfactant/gsample. By way of contrast, exposing the sample to silica nanoparticlesin artificial seawater prior to exposing the sample to the SDSsurfactant significantly reduced the amount of SDS surfactant adsorbedby the sample. For example, the adsorption of the SDS was decreased from0.81 mg/g to about 0.26 mg/g, a decrease of over two-thirds.

Accordingly, providing a suspension including nanoparticles and anionicsurfactants or sequentially providing nanoparticles and anionicsurfactants to the material (e.g., the subterranean formation, oilsands, bitumen, etc.) may substantially reduce an amount of surfactantthat adsorbs onto surfaces thereof. The nanoparticles may alter ahydrocarbon-water interface in the presence of the anionic surfactant.The nanoparticles may mobilize hydrocarbons from the material bydisjoining pressure. The anionic surfactants may form a wedge at aninterface between the surfaces of the material, a hydrocarbon phase, andan aqueous phase. The combination of the nanoparticles and thesurfactant may improve surfactant performance within the material, evenwhen exposed to high temperatures (e.g., a temperature greater thanabout 50° C., a temperature greater than about 60° C., a temperaturegreater than about 70° C., or even a temperature greater than about 80°C.) and high salinity.

Additional nonlimiting example embodiments of the disclosure aredescribed below.

Embodiment 1: A method of recovering hydrocarbons from a subterraneanformation, the method comprising: introducing a suspension comprising atleast one of silica nanoparticles or aluminum silicate nanoparticlesinto a subterranean formation; contacting surfaces of the subterraneanformation with the suspension to form a layer of the at least one ofsilica nanoparticles or aluminum silicate nanoparticles on at least somesurfaces of the subterranean formation; after introducing the suspensioncomprising the at least one of silica nanoparticles or aluminum silicatenanoparticles into the subterranean formation, introducing a solutioncomprising at least one anionic surfactant into the subterraneanformation; and extracting hydrocarbons from the subterranean formation.

Embodiment 2: The method of Embodiment 1, further comprising selectingthe at least one of silica nanoparticles or aluminum silicatenanoparticles to have a diameter less than about 100 nm.

Embodiment 3: The method of Embodiment 1 or Embodiment 2, whereinintroducing a solution comprising at least one anionic surfactant intothe subterranean formation comprises introducing a solution comprisingat least one anionic surfactant and the at least one of silicananoparticles or the aluminum silicate nanoparticles into thesubterranean formation simultaneously.

Embodiment 4: The method of any one of Embodiments 1 through 3, furthercomprising selecting the at least one anionic surfactant to comprisesodium dodecyl sulfate.

Embodiment 5: The method of any one of Embodiments 1 through 4, whereinintroducing a solution comprising at least one anionic surfactant intothe subterranean formation comprises introducing the solution into asubterranean formation having a temperature greater than about 80° C.

Embodiment 6: The method of any one of Embodiments 1 through 5, whereinintroducing a suspension comprising at least one of silica nanoparticlesor aluminum silicate nanoparticles into a subterranean formationcomprises introducing a suspension comprising silica nanoparticlesdispersed in a brine carrier fluid into the subterranean formation.

Embodiment 7: The method of any one of Embodiments 1 through 6, furthercomprising forming the solution to include between about 10 ppm andabout 50,000 ppm of the at least one anionic surfactant.

Embodiment 8: The method of any one of Embodiments 1 through 7, furthercomprising selecting the at least one of silica nanoparticles oraluminum silicate nanoparticles to include at least one anionicfunctional group.

Embodiment 9: The method of any one of Embodiments 1 through 8, furthercomprising at least one of water flooding and steam flooding thesubterranean formation prior to introducing the suspension comprisingthe at least one of silica nanoparticles or aluminum silicatenanoparticles into the subterranean formation.

Embodiment 10: The method of any one of Embodiments 1 through 9, whereinintroducing a solution comprising at least one anionic surfactant intothe subterranean formation comprises introducing a solution comprisingadditional nanoparticles into the subterranean formation, wherein theadditional nanoparticles are different from the at least one of silicananoparticles or aluminum silicate nanoparticles in the suspension.

Embodiment 11: The method of any one of Embodiments 1 through 10,further comprising selecting the at least one of silica nanoparticles oraluminum silicate nanoparticles to comprise at least one functionalgroup formulated and configured to react with hydroxyl groups onsurfaces of the subterranean formation.

Embodiment 12: A method of recovering hydrocarbons from a subterraneanformation, the method comprising: mixing nanoparticles having a diameterless than about 100 nm with a carrier fluid comprising brine and atleast one anionic surfactant to form a suspension, the nanoparticlescomprising silica nanoparticles, aluminum silicate nanoparticles, or acombination thereof; introducing the suspension into a subterraneanformation having a temperature greater than about 50° C.; and extractinghydrocarbons from the subterranean formation.

Embodiment 13: The method of Embodiment 12, further comprising selectingthe at least one anionic surfactant to comprise a sulfate or asulfonate.

Embodiment 14: The method of Embodiment 12 or Embodiment 13, furthercomprising selecting the at least one anionic surfactant to comprise aphosphate.

Embodiment 15: The method of any one of Embodiments 12 through 14,further comprising selecting the at least one anionic surfactant tocomprise at least one carboxylate surfactant and at least one sulfonatesurfactant.

Embodiment 16: The method of any one of Embodiments 12 through 15,further comprising selecting the nanoparticles to comprise at least afirst type of silica nanoparticle and at least a second type of silicananoparticle.

Embodiment 17: The method of any one of Embodiments 12 through 16,further comprising: selecting the first type of silica nanoparticles tocomprise silica nanoparticles including at least one functional group;and selecting the second type of silica nanoparticles to besubstantially free of functional groups.

Embodiment 18: The method of any one of Embodiments 12 through 17,further comprising selecting the nanoparticles to comprise aluminumsilicate nanoparticles.

Embodiment 19: The method of any one of Embodiments 12 through 18,further comprising introducing another suspension comprisingnanoparticles into the subterranean formation prior to introducing thesuspension comprising the nanoparticles and the at least one anionicsurfactant into the subterranean formation.

Embodiment 20: A method of recovering hydrocarbons from a subterraneanformation, the method comprising: introducing a suspension comprisingnanoparticles selected from the group consisting of silica and aluminumsilicate into a subterranean formation; adhering the nanoparticles tosurfaces within the subterranean formation; and after introducing thesuspension comprising nanoparticles into the subterranean formation,introducing a solution comprising at least one anionic surfactant intothe subterranean formation.

Embodiment 21: A method of recovering hydrocarbons, the methodcomprising: introducing a suspension comprising nanoparticles to amaterial; contacting surfaces of the material with the suspension; afterintroducing the suspension comprising the nanoparticles to the material,introducing at least one charged surfactant to the material; andremoving hydrocarbons from the material.

Embodiment 22: The method of Embodiment 21, wherein contacting surfacesof the material with the suspension comprises forming a layer of thenanoparticles on the surfaces of the material.

Embodiment 23: The method of Embodiment 21 or Embodiment 22, whereinintroducing at least one charged surfactant to the material comprisesintroducing an anionic surfactant to the material.

Embodiment 24: The method of any one of Embodiments 21 through 23,wherein introducing a suspension comprising nanoparticles to a materialcomprises introducing at least a first type of silica nanoparticles andat least a second type of silica nanoparticles to the material.

Embodiment 25: The method of any one of Embodiments 21 through 24,wherein introducing at least one charged surfactant to the materialcomprises introducing the solution into a subterranean formation havinga temperature greater than about 50° C.

Embodiment 26: The method of any one of Embodiments 21 through 25,wherein introducing a suspension comprising nanoparticles to a materialcomprises introducing a suspension including nanoparticles comprisingaluminum atoms and silicon atoms to the material.

Embodiment 27: The method of any one of Embodiments 21 through 26,wherein introducing a suspension comprising nanoparticles to a materialcomprises introducing a suspension comprising one of silicananoparticles, functionalized silica nanoparticles, aluminum silicatenanoparticles, alumina modified silica nanoparticles, metal oxidemodified nanoparticles, functionalized alumina modified silicananoparticles, and functionalized metal oxide modified nanoparticles tothe material.

Embodiment 28: The method of any one of Embodiments 21 through 27,further comprising selecting the nanoparticles to include at least oneanionic functional group

Embodiment 29: The method of any one of Embodiments 21 through 28,wherein introducing a suspension to a material comprises introducing asuspension into a subterranean formation, further comprising at leastone of water flooding and steam flooding the subterranean formationprior to introducing the suspension into the subterranean formation.

Embodiment 30: The method of any one of Embodiments 21 through 29,wherein introducing at least one charged surfactant to the materialcomprises introducing a solution comprising additional nanoparticles andthe at least one charged surfactant to the material.

Embodiment 31: The method of any one of Embodiments 21 through 30,further comprising selecting the nanoparticles to comprise at least onefunctional group formulated and configured to react with hydroxyl groupson surfaces of material.

Embodiment 32: A method of recovering hydrocarbons, the methodcomprising: introducing a fluid comprising at least one chargedsurfactant and nanoparticles comprising aluminum atoms and silicon atomsto a material at a temperature greater than about 50° C.; and removinghydrocarbons from the material.

Embodiment 33: The method of Embodiment 32, further comprising selectingthe at least one charged surfactant to comprise a sulfate or asulfonate.

Embodiment 34: The method of Embodiment 32 or Embodiment 33, furthercomprising selecting the at least one charged surfactant to comprise atleast one carboxylate surfactant and at least one sulfonate surfactant.

Embodiment 35: The method of any one of Embodiments 32 through 34,further comprising selecting the at least one charged surfactant tocomprise sodium dodecyl sulfate.

Embodiment 36: The method of any one of Embodiments 32 through 35,further comprising selecting the nanoparticles to comprise aluminamodified silica nanoparticles.

Embodiment 37: The method of any one of Embodiments 32 through 36,wherein introducing a fluid comprising at least one charged surfactantand nanoparticles to a material comprises introducing a fluidcomprising: first nanoparticles functionalized with at least a firsttype of functional group; and second nanoparticles functionalized withat least a second type of function group.

Embodiment 38: The method of any one of Embodiments 32 through 37,further comprising selecting the nanoparticles to comprise aluminumsilicate nanoparticles.

Embodiment 39: The method of any one of Embodiments 32 through 38,further comprising introducing another fluid comprising nanoparticles tothe material prior to introducing the fluid comprising the at least onesurfactant and nanoparticles to the material.

Embodiment 40: A method of recovering hydrocarbons, the methodcomprising: introducing nanoparticles selected from the group consistingof silica, aluminum silicate, and alumina modified silica nanoparticles,and metal oxide modified nanoparticles; adhering the nanoparticles tothe material; and after introducing the nanoparticles to the material,introducing at least one surfactant to the material.

While the disclosure is susceptible to various modifications andalternative forms, specific embodiments have been shown by way ofexample in the drawings and have been described in detail herein.However, the disclosure is not intended to be limited to the particularforms disclosed. Rather, the disclosure is to cover all modifications,equivalents, and alternatives falling within the scope of the disclosureas defined by the following appended claims and their legal equivalents.

What is claimed is:
 1. A method of recovering hydrocarbons, the methodcomprising: introducing a fluid comprising at least one chargedsurfactant and nanoparticles comprising aluminum silicate into aformation comprising hydrocarbons; and removing the hydrocarbons fromthe formation.
 2. The method of claim 1, wherein introducing a fluidcomprises introducing a fluid comprising the at least one chargedsurfactant including a same group as functional groups of thenanoparticles.
 3. The method of claim 1, wherein introducing a fluidcomprising at least one charged surfactant into the formation comprisesintroducing a fluid comprising at least one charged surfactantcomprising at least one carboxylate surfactant and at least onesulfonate surfactant into the formation.
 4. The method of claim 1,wherein introducing a fluid comprising at least one charged surfactantinto the formation comprises introducing a fluid comprising at least onecharged surfactant comprising sodium dodecyl sulfate into the formation.5. The method of claim 1, introducing a fluid comprising at least onecharged surfactant and nanoparticles comprising aluminum silicate into aformation comprises introducing a fluid comprising alumina modifiedsilica nanoparticles and aluminum silicate into the formation.
 6. Themethod of claim 1, wherein introducing a fluid comprising at least onecharged surfactant and nanoparticles comprising aluminum silicate into aformation comprises introducing a fluid into the formation, the fluidcomprising: first nanoparticles functionalized with at least a firsttype of functional group; and second nanoparticles functionalized withat least a second type of functional group.
 7. The method of claim 1,further comprising selecting the nanoparticles to comprise aluminumsilicate nanoparticles.
 8. The method of claim 1, further comprisingintroducing an additional fluid comprising additional nanoparticles andsubstantially free of surfactant to the formation prior to introducingthe fluid to the formation.
 9. The method of claim 1, whereinintroducing a fluid comprising at least one charged surfactant andnanoparticles comprising aluminum silicate into a formation comprisesintroducing, into the formation, a fluid comprising nanoparticlesselected from the group consisting of one or more of Al₂SiO₅(Al₂O₃.SiO₂), Al₂Si₂O₅(OH)₅ (Al₂O₃.2SiO₂.2H2O), Al₂Si₂O₇ (Al₂O₃.2SiO₂),Al₆SiO₁₃ (3AlO₃.2SiO₂), and Al₄SiO₈ (2Al₂O₃.SiO₂).
 10. The method ofclaim 1, wherein introducing a fluid comprising at least one chargedsurfactant and nanoparticles comprising aluminum silicate into aformation comprises introducing, into the formation, a fluid comprisingaluminum silicate nanoparticles functionalized with one or more of analkyl silane, an aryl silane, (3-aminopropyl)triethoxysilane (APTES),(3-glycidylkoxypropyl)trimethoxysilane (also referred to as glymosilane), polyethylene glycol (PEG), and one or more carbohydrates. 11.The method of claim 1, wherein introducing a fluid comprising at leastone charged surfactant and nanoparticles comprising aluminum silicateinto a formation comprises introducing, into the formation, aluminumsilicate nanoparticles including at least one silicon-carbon bond.
 12. Amethod of recovering hydrocarbons from a subterranean formation, themethod comprising: mixing aluminum silicate nanoparticles with a carrierfluid comprising at least one anionic surfactant to form a suspension;introducing the suspension into a subterranean formation, the suspensionhaving a temperature greater than about 50° C.; and extractinghydrocarbons from the subterranean formation.
 13. The method of claim12, wherein mixing aluminum silicate nanoparticles with a carrier fluidcomprises mixing aluminum silicate nanoparticles having a diameter lessthan about 100 nm with the carrier fluid.
 14. The method of claim 12,wherein mixing aluminum silicate nanoparticles with a carrier fluidcomprises mixing aluminum silicate nanoparticles with a carrier fluidcomprising brine.
 15. The method of claim 12, wherein mixing aluminumsilicate nanoparticles with a carrier fluid comprising at least oneanionic surfactant to form a suspension comprises forming the suspensionto comprise a greater concentration of the at least one anionicsurfactant than a concentration of the aluminum silicate nanoparticles.16. The method of claim 15, wherein forming the suspension to comprise agreater concentration of the at least one anionic surfactant than aconcentration of the aluminum silicate nanoparticles comprises formingthe suspension to comprise a concentration of the at least one anionicsurfactant greater than about 2.0 times the concentration of thealuminum silicate nanoparticles.
 17. The method of claim 12, whereinforming the suspension to comprise a greater concentration of the atleast one anionic surfactant than a concentration of the aluminumsilicate nanoparticles comprises forming the suspension to exhibit a pHgreater than about 9.0.
 18. The method of claim 12, wherein introducingthe suspension into a subterranean formation comprises adhering thenanoparticles to surfaces of the subterranean formation.
 19. The methodof claim 12, wherein introducing the suspension into a subterraneanformation comprises adhering a greater number of nanoparticles tosurfaces of the formation than the at least one anionic surfactant. 20.The method of claim 12, further comprising flooding the subterraneanformation with artificial sea water (ASW) prior to introducing thesuspension into the subterranean formation.